1. Field of the Invention
The present invention pertains to the field of automated oilfield separator systems for use in measuring production volumes including a mixture of oil, gas, and water components. More specifically, the separator system utilizes a Coriolis flowmeter, a densitometer, and a water-cut probe to measure production volumes of the respective components or phases of the production mixture.
2. Statement of the Problem
Oil and gas wells reach beneath the earth's surface to drain rock formations where producible quantities of oil and gas have become trapped. Oil, gas, and water can simultaneously flow into the well from a single producing formation. This multiphase flow of oil, gas, and water results in a production mixture that may be separated into its respective components. It is desirable to separate the production mixture including oil, gas, and water components into its respective components because commercial markets normally exist for only the oil and gas. No market exists for the Water because it is typically saltwater that can create a disposal problem. Oil and gas production is often associated with the production of a significant amount of water because it is commercially feasible to produce these wells until the pumping costs plus the cost of saltwater disposal exceed the revenue derived from oil and gas sales.
An oilfield typically extends over a plurality of mineral-right leases. Each lease or a group of leases typically has an operator that oversees the efforts to produce a particular set of wells. The operator must acquire well test data before the operator can properly manage the lease. Well test data includes wellhead pressure data, as well as the volumetric flow rates for the respective oil, gas, and water components of a production mixture that originates from a single well. The lease operator requires well test information for a proper allocation of the revenue derived from each producing well among the various ownership interests in that well. Additionally, the lease operator requires well test information to conduct engineering studies that attempt to optimize the production performance of the field as a whole. For example, an engineer could choose to shut-in oil production from a well having an excessively high water cut, and convert the well into a water injection well to assist an ongoing waterflood.
The producing wells in an oilfield or a portion of an oilfield often share a production facility including a main production separator, a well test separator, pipeline transportation access, saltwater disposal wells, and safety control features. The use of common or shared production facilities prevents the operator from having to spend additional capital for redundant facilities.
The test separator is used to facilitate the measurement of volumetric flow rate information from the production materials that derive from a single well. The measurements include volumetric flow rates of the respective oil, gas, and water phases, e.g., 95 barrels of water per day, 5 barrels of oil per day, and 6 MCF of gas per day. Another useful measurement is the `water-cut` measurement. The term `water-cut` is hereby defined as any ratio that represents a relationship between a volume of oil and a volume of water in an oil and water mixture. According to the most conventional usage of the term `water-cut`, well production fluids in the above example would have a 95% water-cut because water comprises 95 of the total 100 barrels of oil and water liquids. The term `water-cut` is sometimes also used to indicate a ratio of the total volume of oil produced to the total volume of water produced. A term `oil-cut` could imply the oil volume divided by the combined oil and water volume. As defined herein, the term `water-cut` encompasses all of these alternative definitions.
The main production separator and the well test separator are each used to separate the respective oil, gas, and water components that arrive at the production facility as a mixture of these phases or components. The main production separator receives combined production volumes from multiple wells to prepare these volumes for eventual sale. The test separator typically has a reduced throughput capacity in comparison to the main production separator, and is provided for use in measuring production rates that derive from a single well. As used herein, the term "phase" refers to a type of fluid that may exist in contact with other fluids, e.g., a mixture of oil and water includes a discrete oil phase and a discrete water phase. Similarly, a mixture of oil, gas, and water includes a discrete gas phase and a discrete liquid phase with the liquid phase including an oil phase and a water phase. Industry terminology refers to a `two-phase` separator as one that is used to separate a gas phase from a liquid phase including oil and water. A `three-phase` separator is used to separate the gas from the liquid phases and also separates the liquid phase into oil and water phases.
As compared to two phase separators, three phase separators require additional valve and weir assemblies, and typically have larger volumes to permit longer residence times of produced materials for gravity separation of the production materials into their respective oil, gas, and water components. The use of a three phase test separator permits direct measurement of the separated components. Error exists even in this direct measurement because water is seldom, if ever, completely removed from the segregated oil component at the production facility. A residual water content of up to about ten percent typically remains in the segregated oil component even after a separator is used to remove most of the water from the oil component.
Two phase separators cost less, halve a much simpler design, and require less maintenance than do three phase separators. The use of a two phase separator typically does not permit direct volumetric measurements to be obtained from the segregated liquid (oil and water) components under actual producing conditions. The use of a single Coriolis flowmeter in combination with a two phase separator advantageously permits measurement of the respective oil and water volumes in the liquid phase leaving the test separator.
The use of a capacitance or resistance probe to measure water-cut in produced fluids is known in the industry. These water-cut monitors operate on the principle that oil and water have drastically different dielectric constants. Thus, a water-cut probe can measure the volumetric percentage of water in a combined oil and water flow stream. These monitors, however, provide acceptably accurate water-cut measurements only where the water volume is less than about 20% to 30% of the total flow stream. The upper 30% accuracy limit is far below the level that is observed from many producing wells. For example, the total liquid production volume of an oil well can be 99% water. Water-cut monitors, therefore, are relegated to determining the water-cut in an oil component that has a low water content. Water-cut monitors most often cannot be used to determine the water content in the material that flows from a two phase separator because the total liquid component has a water content that exceeds the 30% upper accuracy limit.
It is necessary to convert the Coriolis-based mass flow rates into volumes because oilfield production is conventionally sold as volume, not mass. Conventional Coriolis meters have a variety of capabilities in addition to their ability to perform mass flow rate measurements. The structure of a conventional Coriolis mass flowmeter can also be operated as a vibrating-tube densitometer because the mass flowmeter works on the principle of vibrating tubes that act as a spring and mass system. These density values are used to convert the total mass flow rate measurements into volumetric values. Nevertheless, the volumetric measurement pertains to the total combined flow stream.
Numerous difficulties exist in using a Coriolis flowmeter to identify the respective mass percentages of oil, gas, and water in a total combined flow stream. A Coriolis mass flowmeter can be used to determine the total mass flow rate and allocate the total mass flow rate to the respective components or phases in the combined flow stream. This calculation technique is especially useful in determining the mass distribution of two phase (e.g., oil and water) flows. Even so, the technique, presently requires laboratory analysis of manually obtained samples to provide density data for use in the volumetric flow rate and water-cut calculation.
U.S. Pat. No. 5,029,482 teaches the use of empirically-derived correlations that are obtained by flowing combined gas and liquid flow streams having known mass percentages of the respective gas and liquid components through a Coriolis meter. The empirically-derived correlations are then used to calculate the percentage of gas and the percentage of liquid in a combined gas and liquid flow stream of unknown gas and liquid percentages based upon a direct Coriolis measurement of the total mass flow rate.
U.S. Pat. No. 4,773,257 teaches that a water fraction of a total oil and water flow stream may be calculated as set forth below in Equation (1): EQU X.sub.w =(D.sub.e -D.sub.o,T)/(D.sub.w,T -D.sub.o,T), (1)
wherein X.sub.w is a mass-based fraction of water in the total combined oil and water flow stream; D.sub.e is a density of the total combined oil and water flow stream at a measurement temperature T; D.sub.oT is a known density of the pure oil component in the total combined flow stream at measurement temperature T; and D.sub.w,T is a known density of water in the total combined flow stream at measurement temperature T. The values D.sub.o,T and D.sub.w,T can be corrected for temperature effects according to Equations (2) and (3) below: EQU D.sub.o,T =D.sub.o *-C.sub.o (T-Tr) (2) EQU D.sub.w,T =D.sub.w *-C.sub.w (T-Tr), (3)
wherein D.sub.o * is an oil density at a reference temperature T.sub.r (which is conventionally chosen as 60.degree. F.); D.sub.w * is a water density at the reference temperature T.sub.r ; C.sub.o is a thermal expansion coefficient for oil; C.sub.w is a thermal expansion coefficient for water; and the remaining variables are defined above. Those skilled in the art will understand that the thermal expansion coefficients C.sub.o and C.sub.w, as well as other correlations that correct densities for temperature, can be obtained from various sources including publications by the American Petroleum Institute.
A total volumetric flow rate is calculated according to Formula (4): EQU Q.sub.e =M.sub.e /D.sub.e, (4)
wherein Q.sub.e is a Coriolis-based mass flow rate measurement obtained from the total combined oil and water flow stream; and the remaining terms are defined above.
A volumetric flow rate of oil is calculated according to Equation (5): EQU Q.sub.o =Q.sub.e (1-X.sub.w), (5)
wherein Q.sub.o is a volumetric flow rate of oil, and the remaining variables are defined above.
A volumetric flow rate of water is calculated according to Equation (6): EQU Q.sub.w =Q.sub.e *X.sub.w, (6)
wherein Q.sub.w is a volumetric flow rate of water, and the remaining variables are defined above.
The volumetric flow rate values Q.sub.o and Q.sub.w can be corrected to a standard reference temperature, T.sub.r, through multiplication of the volumetric flow rate values by the density at a measurement temperature and dividing by the density at the reference temperature, e.g., as in Formula (7): EQU Q.sub.o *=Q.sub.o,T *D.sub.o,T /D.sub.o *, (7)
wherein Q.sub.o is a volumetric oil flow rate at a standard reference temperature T.sub.r ; Q.sub.o,T is a volumetric oil flow rate measured at temperature T and calculated according to Equation (5); and the remaining variables are defined above.
A significant problem exists in the use of Equations (1)-(7) because the density values D.sub.o,T and D.sub.w,T must be measured from samples that are manually obtained from a specific producing well. In the absence of laboratory measurements, it remains impossible to convert the phase-adjusted mass flow rate information into oil and water volumes because the Coriolis meter cannot produce an oil density and a water density value by direct measurement of the combined flow stream. The circumstances under which the samples are taken oftentimes provide a source of error in the laboratory measurements because the sample is exposed to atmospheric pressure. The exposure to atmospheric pressure removes gas from solution, and the resultant sample has a relatively increased density as compared to the former pressurized sample. Additionally, it is nearly impossible to provide laboratory measurement conditions that replicate the field conditions. The density values of produced fluids often change over the life of a producing well. Therefore, periodic sampling of the production fluids is required. The laboratory measurements are, accordingly, disposed to inherent error for lack of timeliness in sampling the fluids and an inability to replicate production line conditions in the laboratory.
A direct density measurement derived from the Coriolis meter cannot be used in the volumetric calculation because it is most often impossible to obtain a satisfactory direct density measurement from the separate oil component. Even if a separator is used to separate the oil component from the water component, the separated oil phase retains up to about ten percent water by volume. The residual water causes an error in the direct density measurement.
Another source of volumetric inaccuracy in Well test measurements pertains to solution gas that is liberated at reduced pressures. The pressure-volume-temperature behavior of the produced fluid can cause appreciable differences in the measured quantities of separated oil and gas that are obtained from the production mixture. A reduced pressure will liberate gas from the oil phase. An increased pressure drives gas back into solution. It is, accordingly, desirable that the test separator conditions approximate the conditions of the main production separator.
The pressure within the test separator may be different from that in the main production separator. Two phase well test separators often flash the production fluid by liberating gas from the fluid at reduced pressure as the liquids are drained from the separators. No effort is made to control the test separator pressure while the liquids are drained because it is commonly believed that the separated production components will be recombined in the main production separator for eventual sale. The failure to control test pressures results in erroneous volumetric measurements because the reduced gas pressure causes solution-gas to leave the oil phase. The liquid volume is, accordingly, reduced, and the liquid has a greater density.
A true need exists for a Coriolis-based flowmeter that can measure Volumetric flow rates for the respective phases or components in a total production stream without requiring laboratory measurements on hand samples of the production stream to provide the density values for the respective components. Additionally, there is a need for a test separator system that utilizes sales line or main production separator conditions throughout its measurement cycle to preserve the integrity of the volumetric test measurements.